Clathrate hydrate plug formation in oil and gas pipelines is a severe problem for the petroleum industry. When water is produced along with gas, oil, or mixtures of both, under the right pressure and temperature conditions, there is a potential to form a solid hydrate phase. Pressure-temperature conditions favorable for hydrate formation are commonly encountered during the winter in fields onshore and in shallow water depths offshore, and regularly in deepwater (>1,500 feet water depth) fields offshore. As a rule of thumb, at a seafloor temperature of about 40° F. for water depths greater than 3,000 feet, hydrates can form in a typical natural gas pipeline at pressures as low as 250 psi. As solid hydrates form, the hydrates can deposit on the pipe walls or agglomerate into larger solid masses creating obstructions to flow.
Technologies currently used to prevent hydrate blockage formation include dehydration, heat and/or pressure management or chemical injection with thermodynamic or low dosage hydrate inhibitors (LDHI). Dehydration is simply removing most of the water from the hydrocarbon stream so that too little is left to form hydrate blockages. Temperature or pressure control is used to operate a system outside of conditions that can promote hydrate formation. The addition of thermodynamic inhibitors (typically alcohols, glycols or salts) produces an anti-freeze like effect that shifts the hydrate phase equilibrium condition to lower temperatures at a given pressure so that a system may be operated safely outside the hydrate stability region. LDHI act in one of two ways: 1) as a kinetic inhibitor, or 2) as an anti-agglomerant. Kinetic LDHIs merely slow the hydrate formation rate so that formation of a solid blockage is retarded during the residence time of the fluids in the pipeline. Anti-agglomerant LDHIs allow the hydrates to form, but keep the hydrate particles dispersed in a liquid hydrocarbon phase. Anti-agglomerant LDHIs are also known to have limitations on the water cut in which the chemicals can work. They are usually recommended for application for water cuts of less than 50%.
Each of these solutions for hydrate prevention can work, but all require significant capital or operating expense. The thermal and dehydration options are capital intensive, the thermodynamic inhibitor options are both capital and operationally intensive, and the LDHI option is operationally intensive. LDHIs also have additional risk associated with their application due to the relative immaturity of the technology. Additionally, discharge water quality (toxicity) and crude quality (methanol content for example) issues can be a concern when using both thermodynamic inhibitors and LDHIs. There is also a general concern in the industry that as remote deepwater fields mature, water cuts may become high to the point where chemical injection for hydrate inhibition may offer considerable challenges—either due to the sheer volumes of thermodynamic inhibitor required or due to limitations on LDHI performance as mentioned above. Therefore, the issue of a cost-effective and reliable hydrate inhibition strategy for fields with high water cuts is a major challenge facing the industry.
There are additional flow assurance issues commonly found with low-temperature high pressure flow in flow lines. In cases where there is water in an oil emulsion, such an emulsion can have high viscosity leading to problems associated with excessive pressure drop. The present invention, to be described hereafter, addresses the challenges described above.